Method for exhaust gas treatment in a solid oxide fuel cell power plant

ABSTRACT

The invention relates to anode exhaust gas treatment methods for solid oxide fuel cell power plants with CO2 capture, in which the unreacted fuel in the anode exhaust ( 301 ) is recovered and recycled, while the resulting exhaust stream ( 303 ) consists of highly concentrated CO2. It is essential to the invention that the anode fuel gas ( 102 ) and the cathode air ( 205 ) are kept separate throughout the solid oxide fuel cell stacks ( 1 ). A gas turbine ( 202,207 ) is included on the air side in order to maximise the electrical efficiency.

BACKGROUND

1. Field of the Invention

The invention relates to methods for anode exhaust treatment in solidoxide fuel cell power plants where the air stream and fuel stream iskept separate throughout the system. Particularly, the invention relatesto solutions for recovering and recycling the unspent fuel from theanode fuel exhaust gas.

2. Background Information

An increasing demand for electric power combined with increasingenvironmental awareness has initiated extensive research for developingcost effective and environmentally friendly power generation. Althoughseveral renewable power sources are available, only nuclear andhydrocarbon fuelled power plants can supply the bulk of the power beingdemanded. Nuclear power plants suffer from safety risks and problematicradioactive waste disposal. Future development of nuclear power plantsseems very limited, mostly due to lack of political acceptance. Thus,power plants based on fossil fuels are called upon to fill most of theenergy gap. However, a continuous development of scientific data on theGreenhouse effect and political agreements such as the Kyoto protocolfrom 1997, is generating an increasing push towards limiting andreducing greenhouse gas emissions. As a result of this trend, severalcountries seek to limit their carbon dioxide (CO₂) emissions andestablish annual maximum emission levels. In this endeavour, CO₂emissions from fossil fuel power plants is a main concern since suchplants are a considerable source of CO₂ emissions. As an example, aboutone third of the US CO₂ emissions come from such power plants.Typically, the CO₂ emissions from a natural gas based power plantproducing 3 TWh per year would be in the order of 1.1 million tons peryear [ref. Gassm.]. It is therefore desired to develop efficient fossilfuel power plants with capture of CO₂ that subsequently can besequestered. Sequestration of the CO₂, produced from a large-scale powerplant, will most likely be achieved by injection as gas, liquid orhydrates into subterranean formations or into deep seawater. Acommercial value for the produced CO₂ may be obtained when used forenhanced oil recovery in producing oil fields.

Several processes/concepts for power production from fossil fuels withgreatly reduced CO₂ emissions are known in the art. These processesproduce concentrated and pressurised CO₂ suitable for sequestration orindustrial usage. The methods for recovering the CO₂ from natural gasbased power production may be divided into three main categories, i.e.:

1) Pre-combustion decarbonisation

-   -   2) Oxyfuel or oxygen-fired combustion    -   3) Post-combustion CO₂-capture

Precombustion involves a “decarbonisation” of the fuel prior to usage ina standard Gas Turbine Combined Cycle power plant (GTCC) plant oralternative power producing technology based on fossil fuels. As atypical example, such a process would include reformation, water gasshift, and CO₂ removal by chemical absorption using conventional aminesystems. The resulting fuel gas is hydrogen-rich and may be used in somegas turbines. An advantage of this concept is that it is essentiallybased on a series of known unit operations. There is however only asmall number of gas turbines available that may use the hydrogen richgas as fuel. Therefore, unless modifications/qualifications of other gasturbines are made, this concept will not be available at differentscales. The most economical scales for the components are large and thespecific costs and efficiencies will suffer as the scale is reduced.Another disadvantage of applying conventional CO₂ removal solutions inprecombustion is that they are operated at low temperature, requiringcooling and reheating of the gas due to the CO₂ removal. This conceptwill have an efficiency that is lower than for a standard GTCC plant orother alternative technology. The precombustion are typically consideredcombined with other less developed power producing technologies such asfuel cells. Also, other emerging CO₂ removal technologies are typicallyconsidered in the literature such as CO₂ selective membranes, hybridsorbent/membrane systems, physical or chemical sorbents.

The Oxyfuel category includes concepts supplying the oxygen used tooxidise the natural gas in such a manner that nitrogen does not enterthe reaction zone. The combustion products are, in principle, only CO₂and H₂O. The water is removed by cooling/condensation of the combustionproducts and the result is a nearly pure CO₂ gas stream. One way ofkeeping nitrogen away from the reaction zone is to produce oxygen in aconventional cryogenic air separation unit prior to combustion. Othervariations include usage of high temperature ceramic oxygen transfermembranes to produce oxygen or supply of oxygen by means of a metallicoxygen carrier (chemical looping combustion). One example of a oxyfuelconcept is a process based on oxygen production in a conventional airseparation unit(s) (ASU), combustion in a specialised gas turbine,utilisation of heat in a steam bottoming cycle and recycle of gasturbine exhaust (CO₂/H₂O) for temperature control. For plant sizes belowapp. 200 MW, the cryogenic air separation units must be sized down fromthe optimum scale. This gives a considerable cost penalty in the 10-50MW scale. Further, a smaller scale gas turbine with higher specific costand lower performance must be assumed. Also the use of CO₂/H₂O recycleto control the temperature will consume energy at the expense of totalefficiency. Both investment cost and energy consumption are very highfor generation of oxygen at the purity and quantity required in Oxyfuelcycles. Most of the prior art has required the use of a source of highlyconcentrated oxygen, ref. U.S. Pat. No. 5,724,805, U.S. Pat. No.5,956,937 and U.S. Pat. No. 5,247,791. In order to reduce the cost ofoxygen, it is a goal to include the use of oxygen selective iontransport membranes in Oxyfuel cycles. This implies that a way toachieve a positive oxygen partial pressure differential and the requiredtemperature, must be found. A conventional heat recovery system isproposed to utilize the heat emitted by the cycle. These are costly, andmore economical ways for the utilization of this heat energy aredemanded.

Postcombustion is based on cleaning of the exhaust from a GTCC plant orother power producing technology based on fossil fuels. The exhauststream typically contains roughly 3-4 vol % CO₂ that may be removed fromthe exhaust in a wet scrubbing process involving chemical absorptionusing an amine based absorbent. Heat (steam from the power plant) isrequired to disassociate the CO₂ from the absorbent. The result is analmost 100% pure CO₂ gas at atmospheric pressure that can be pressurisedfor transport and disposal. This technology can be retrofitted toexisting plants and also it may be “turned off” without stopping thepower production from the plant. However, the low concentration of CO₂requires large gas handling systems and the treated exhaust gas willstill contain approximately 15% of the CO₂, also NO_(x) and some amineswill be present in the exhaust gas. The efficiency will be lower thanfor a standard GTCC plant or alternative technologies due to the energyneeded to separate the CO₂. Alternative less developed CO₂ separationtechnologies that typically would be considered are chemical or physicalsorbents or CO₂ selective membranes.

The technologies described above will typically have electricalefficiencies less than 50%. In addition, many of them will still emitabout 10-15% of the CO₂. It is therefore a desire to develop fossil fueldriven power plants with CO₂ capture that is highly efficient, emitsless CO₂ and has a lower cost of energy than prior art technology.

Two separation technologies not mentioned in the description above areof particular interest for present invention, i.e. hydrogen selectivemembranes and cryogenic CO₂ separation.

Various types of hydrogen selective membranes are generally known.Hydrogen separation membranes can typically be categorized into two maintypes:

Microporous types, which comprise polymeric membranes and porousinorganic membranes

Dense types, which comprise self-supporting non-porous metal, non-porousmetal supported on a porous substrate such as porous metal or ceramic,and mixed ionic and electronic conduction materials.

The microporous type of membranes generally has a limited selectivity,while the dense type has “infinite” selectivity.

Polymeric membranes typically cannot be used at operating temperaturesabove 250° C. due to lack of stability and they also are incompatiblewith many chemicals that can be present in the feed stream. Thepolymeric membranes also suffer from a lack of selectivity of hydrogenover other gases and the product gas therefore is relatively impure.

Micro porous inorganic membranes are typically made of silica, alumina,titania, molecular sieve carbon, glass or zeolite. All are fabricatedwith a narrow pore size distribution and exhibits high hydrogenpermeability but relatively low selectivity due to the relatively largemean pore diameter. Typical operating temperature for a silica membranewould be <300˜400° C.

Dense membranes normally consist of palladium or palladium alloys ormixed ionic and electronic conducting materials. The Pd and Pd-alloybased membranes typically consist of a thin non-porous or dense film orfoil of Pd or Pd-alloys coated on a porous support of ceramics or porousstainless steel. The thickness of the Pd or Pd alloys film is at presenttypically 70 to 100 μm for commercial membranes (small scale) and due tothe high price of Pd this makes these membranes very expensive and thethickness also results in low permeance. It is essential to have verythin Pd or Pd-alloy films/foils to get a high permeance and anacceptable price. Supported Pd or Pd-alloy membranes of much thinnerfilm thickness are often reported in the literature. Typical operatingtemperatures for Pd and Pd-alloys membranes are in the range 200-500° C.and even higher temperatures have been stated (up to 870° C.).

Mixed ionic and electronic conducting (MIEC) membranes have mostly beenstudied for oxygen separation as described earlier. MIEC membranes forhydrogen separation is far less developed, also compared to Pd-alloymembranes and microporous membranes. These membranes are howeverexpected to develop fast due to the large efforts in developing similaroxygen separating MIEC membranes. The MIEC hydrogen separating membranesfunction by transferring hydrogen as protons and electrons through thedense mixed ceramic material. Typical operating temperatures for themixed ionic and electronic conducting membranes is 600-1000° C.

Cryogenic technology, cooling to temperatures between −40 and −55° C.,for separating CO₂ from a gas stream is conventional technology and verywell known. This technology is also used for cooling and liquefaction ofCO₂. The separation is performed at elevated pressure in order to avoidsolid CO₂ and to increase the required operating temperature. The feedgas to be separated is compressed and dehydrated (to avoid ice) andcooled. After cooling most of the CO₂ is liquefied and the mixture caneasily be separated. Separation can be performed by a simplegravity-based separator or a column could be used in order to obtain apurer CO₂ or less CO₂ in the cleaned gas.

In recent years many solid oxide fuel cell based power plant concepts ofsubstantial size (above 1 MW) have been presented [ref]. These studiesare often based on operation at pressure, typically 3-15 bars. Thisincreases the electrical efficiency and also makes hybrid systemsincluding gas turbines attractive. Typically, the air is compressed andpreheated before entering the SOFC, where electrical power is producedin electrochemical reactions with the fuel and the generated heat ispartly absorbed by the air stream. Subsequently, the hot oxygen depletedair is typically mixed with the spent fuel leaving the anode side andthe mixture is combusted to further increase the gas temperature beforethe heated gas is expanded in a turbine producing additionalelectricity. The pressurised solid oxide fuel cell/gas turbine hybridsystems appears to be very attractive for power production due to thehigh electrical efficiency that can be expected for these systems,typically more than 70% (in the multi-MW range). Examples of typicalpressurised solid oxide fuel cell/gas turbine hybrid concepts that aredescribed in literature can be found in the following references [1, 2,3, 4, 5]. These systems does however all emit the combusted fossil fuelas CO₂ to the atmosphere.

For these typical solutions both precombustion decarbonisation andpostcombustion CO₂ capture methods can be applied in order to make theconcept “zero emission”, but this will be at the expense of efficiencyloss and increased cost as for the other solutions presented.

However, a solid oxide fuel cell system can be classified as an oxyfuelsystem since the oxygen is transferred through the fuel cell wall to theanode side, leaving the nitrogen on the cathode side, provided that theair stream and the fuel stream is kept separated after theelectrochemical reaction.

A so-called zero emission solid oxide fuel cell power pilot plant ofthis type is developed by Shell together with Siemens Westinghouse PowerCorporation. The goal is to use fossil fuels for power generation withhigh efficiency and without emission of CO₂ to the atmosphere. The pilotplant will be operated at atmospheric pressure and will be located atKollsnes in Norway.

There are two major differences to the zero emission solid oxide fuelcell power plant concept compared to those described above. 1) A seal isapplied keeping the cathode air stream separated from the anode fuel gasin such a manner that the two streams are not mixed after the fuel cellreactions. 2) An afterburner is applied in order to further utilise theunreacted fuel leaving the anode side of the fuel cell. Two types ofafterburners has been suggested: 1) An additional SOFC unit operated toconvert the majority of the remaining fuel and producing some additionalelectricity, and 2) using an oxygen transport membrane (OTM) to providethe oxygen for combusting the remaining fuel. The heat released can beused to generate steam for use in a steam turbine. Both he SOFCafterburner and an OTM will be very expensive solutions and give limitedadditional electricity output.

Prior art describes recycle of anode gas in fuel cell systems, ref. U.S.Pat. No. 5,079,103. The described systems use pressure swing adsorption(PSA) for separation of CO₂ from H₂ and CO in the anode exhaust from aSOFC stack. The PSA system operates by adsorption of CO₂ from the anodeexhaust. However, the CO₂ content in this stream is substantial and therequired PSA system will increase the overall cost and complexity.

It is thus desired to find simple and preferably cheap solutions forutilising the remaining unreacted fuel in the anode exhaust gas foradditional power production maintaining a high electrical efficiency andsimultaneously produce clean and preferably pressurised CO₂ stream.

BRIEF DESCRIPTION OF THE INVENTION

The subject invention presents a method for solving the problemsdescribed above. The present invention relates to solid oxide fuel cellsystems having a seal system that keeps the air and fuel streamseparated. Particularly, it relates to the fuel cell anode side exhaustgas treatment in such a system, and more particularly, to exhaust gastreatment methods that separate and recycle the unspent fuel to the mainSOFC. The invention is most suitable for SOFC systems that operate atelevated pressures and are integrated with a gas turbine.

The air is compressed and preheated before it enters the fuel cell stackat the cathode side. Fossil fuel, preferably natural gas, is pretreatedto remove poisons such as sulphur compounds before it is converted bysteam reforming to a mixture of H₂, CO, CO₂ and H₂O. This mixture entersthe fuel cells at the anode side. Oxygen in the air is transferredthrough the fuel cell wall and reacts electrochemically with H₂ and CO,generating electricity and heat. The cathode and anode gas is keptseparate by a seal system.

The oxygen depleted air on the cathode side absorbs heat as it passesthrough the fuel cell on the cathode side. The hot oxygen depleted airis subsequently expanded in a turbine producing additional electricity,heat exchanged with the incoming air and vented.

The anode exhaust can preferably partly be recirculated to the reformersin order to provide the steam required for the steam reforming(otherwise steam must be supplied to the reformers). The remainingfraction of the anode exhaust gas is further treated in two optionalways: 1) in a hydrogen membrane unit and 2) in a cryogenic separationunit.

Using option 1), a high temperature hydrogen membrane unit, the hydrogenin the exhaust gas is transferred through the membrane by a partialpressure difference and as hydrogen is removed from the feed gas side,the water-gas-shift reaction converts more of the remaining CO tohydrogen (the membrane must catalyse water-gas-shift reaction or acatalyst has to be included). A sweep gas such as steam may be appliedon the permeate side to increase the driving force. The anode exhaustgas consists mostly of CO₂ and H₂O after the membrane separation (someH₂ and CO and also N₂ will be present). The water is easily removed andthe result is a concentrated CO₂ stream at roughly the operatingpressure. The permeate hydrogen rich gas is compressed and recirculatedto the fuel cell or reformer, where it is efficiently utilised togenerate electricity.

Using option 2), the cryogenic method the anode exhaust gas is cooled,water is removed before the gas is compressed, cooled, further dried andCO₂ is separated by a gravity-based separator or a column at moderatelylow temperatures. The resulting gas contains mainly hydrogen, CO some N₂and an amount of CO₂ that depends on the separation temperature. Theresulting liquid stream is pressurised CO₂ and can be transported byships or trucks if desired.

Both of these options are advantageous alternatives to pressure swingadsorption for pressurised SOFC systems. By usage of hydrogen selectivemembranes, hydrogen is recovered from the fuel cell anode exhaust. Thefuel stack should in this case be pressurised in order to obtain asgreat driving pressure as possible over the hydrogen selectivemembranes. The membranes may operate at elevated temperature and theamount of hydrogen that has to be removed is relatively small comparedto the amount of CO₂ in the anode exhaust. Additionally, the CO₂ maypass the membranes on the retentive side without large pressure drops.The resulting system is simple and has a very good potential for costsavings. This will in particular apply if the CO₂ is to be captured andexported from the power plant by pipeline. In this case some hydrogen ispermitted in the retentive gas, allowing a non-perfect hydrogen splitand selection of a small hydrogen membrane area. These factors enablehydrogen selective membranes, which now rarely is used, to becompetitive when used in a pressurised fuel cell system with CO₂capture.

Another advantageous option is usage of a cryogenic, gravity basedseparation process. The overall system will then include a combinationof a high temperature SOFC system with a low temperature cryogenicseparation process. A detailed investigation focused on the requiredpurity of the recovered hydrogen and CO will reveal that a substantialamount of diluents are permissible. This enables a relatively simplecryogenic separation process. This option may easily produce liquefiedCO₂ ready for transportation by trucks or ships and is thereforeparticularly beneficial if CO₂ is to be captured and exported and theSOFC stack is pressurised.

An important advantage of potentially cheap and efficientseparation/recycle processes, is that it will be possible to reduce thefuel utilisation in the main SOFC stack. Reduction of the fuelutilisation will increase the voltage and hence increase the SOFCefficiency further. Zero emission solid oxide fuel cell power plantsbased on the concepts of the present invention hold the promise of highefficiency power production from fossil fuels with CO₂ capture, muchhigher efficiency than can be expected for other typical powerproduction systems with CO₂ capture. Another important advantage of thezero emission SOFC/gas turbine hybrid solution is the applicability alsoin the much lower MW range than would be preferred for many of the otherCO₂ capturing solutions presented above.

The membranes of interest for the present invention are the hightemperature hydrogen selective membranes.

Particularly, hydrogen selective membranes including water-gas-shiftactivity are of interest. The major difference of the employment of H₂selective membranes in the present invention compared to otherapplication is that it is used as an exhaust gas treatment method torecover unspent fuel. The embodiment of the present invention does notrequire a very pure hydrogen stream since CO is also a reactant forSOFC. Also, a certain amount of CO₂ can be tolerated (trade-off withlarger gas volumes). The present embodiment also allows for the use of asweep gas, preferably steam, at the permeate side. There will also berelatively small amounts of hydrogen that are going to be recovered andthis reduces the required membrane area needed. Another advantage of thepresent application is that it leaves the CO₂ at high pressure while thehydrogen permeate gas looses pressure. The hydrogen stream flow rate isconsiderably smaller than the CO₂ stream, thus much less compressioncost is required to compress the hydrogen compared to what would beneeded for the CO₂.

The combination of the cryogenic separation with the zero emission SOFCsystem provides a simple and elegant means of separating and recyclingthe unspent fuel. It is relatively cheap and consumes little additionalenergy.

Thereby, the subject invention presents methods that simplifies theanode gas treatment in SOFC cycles with CO₂ capture.

BRIEF FIGURE DESCRIPTION

FIG. 1 is a schematic of the main principles of the present invention.

FIG. 2 is a schematic flow diagram of the present invention showing themain parts of the power plant.

FIG. 3 is a schematic flow diagram of a specific embodiment of thepresent invention using a cryogenic separation process in a power plant.

FIG. 4 is a schematic flow diagram of a specific embodiment of thepresent invention using a separation process based on high temperaturehydrogen selective membranes in a power plant.

FIG. 5 is a schematic flow diagram of a specific embodiment of thepresent invention using a separation process based on high temperaturehydrogen selective membranes in a power plant, in which the recoveredhydrogen is combusted to increase the temperature of the oxygen depletedair.

The invention also allows production of heat and/or steam usable fordistribution to district heating or nearby steam consumers.

DETAILED DESCRIPTION

Referring now in detail to the figures of the drawings, in whichidentical parts have identical reference symbols, and first,particularly, to FIG. 1. FIG. 1. shows the main principles of thepresent invention. The main SOFC stack 1, is divided into an anodesection 2 and a cathode section 3 by a sealing system 4. This sealsystem may be a steam seal. Addition of steam, 5, is needed for thisparticular seal. In order to simplify the schematic, the anode sectioncomprise of all needed reforming steps, as well as optional internalrecycle of part of the anode exhaust to the reformers to provide steamrequired for the steam reforming, or steam addition to the reformers ifinternal recycle of fuel is omitted, in addition to the fuel cells anodeside. No details of the fuel cells are shown. In the present example thefuel cells are of the tubular (one closed end) solid oxide type.Poison-free fuel containing the element carbon 102, typically naturalgas, is fed to the anode side 2, and compressed and preheated air 205 isfed to the cathode side 3 of the main SOFC stack 1. The reformed fuel iselectrochemically reacted with oxygen from the air on the anode side 2of the fuel cell producing electricity and heat. The electricity istypically converted from DC to AC in an inverter 6 The anode exhaust gas301, typically consisting of H₂, CO, CO₂ and H₂O is further transferredto the separation process 302 where the main aim is to separate the CO₂and H₂O from the unspent fuel. The recovered fuel 304 is typicallyrecirculated to the main fuel cell stack.

FIG. 2 is a schematic flow diagram of the present invention showing themain parts of the power plant. A line containing fuel 100, typicallynatural gas, is shown going to a fuel pretreatment unit 101. This fuelpretreament unit contains all necessary poison removal steps to producea fuel that is sufficiently clean to enter the reformer and fuel cellsin the main SOFC unit 1 through line 102. Typically, the pretreatmentunit would consist of desulphurisation by one of the conventionalmethods known to those skilled in the art. The cleaned fuel enters themain SOFC stack and is converted as described for FIG. 1, producingelectricity and heat. The anode exhaust gas is transferred through line301 to the separation process 302 as described for FIG. 1. Theconcentrated CO₂ stream 303 leaving the separation process is typicallyfurther compressed in a conventional compression train 307 before it issent to sequestration 308. The recovered fuel 304 is typically cooled305 before it typically is recycled to the main SOFC. The air stream 201is compressed to the desired operating pressure in a compressor 202,typically the compressor part of a gas turbine. The compressed air 203is preheated in a heater 204 before it enters the cathode side 3 of themain SOFC. The air flowing through the cathode side of the fuel cellabsorbs heat and is vitiated in oxygen. The heated and oxygendepleted-air leaving the main SOFC 206 is expanded in a turbine 207producing additional energy.

FIG. 3 is a schematic flow diagram of a specific embodiment of thepresent invention using a cryogenic separation process in a power plant.The fuel pretreatment 101, main SOFC 1 and gas turbine 201-209 unitshave already been described above. The expanded air 208 is typicallyheat exchanged with the incoming air 203 in a recuperator 204 before itis vented 209. In the present example, the fuel 100, typically naturalgas, enters the fuel pretreatment unit 101 at 8.5 bara and 20° C. and isdesulphurised by passing through a fixed-bed absorbent system. Afterdesulphurisation, the gas 103 is mixed with the recycle gas 329 from theseparation process. The mixture 104 is heat exchanged 105 with the anodeexhaust gas 301 to increase the temperature to about 200° C. Thepreheated gas 106 enters the main SOFC 1 and is converted in severalsteps as described previously. The anode exhaust gas leaves the mainSOFC stack at a temperature of about 800° C. The anode exhaust gastypically consist of 3.0% H₂, 1.6% CO, 33.7% CO₂, 60.0% H₂O and 1.8% N₂.After heat exchange in 105, the water is removed in a condenser orscrubber 310. Additional coolers not shown are used to cool the gas. Thewater 332 is sent to a water treatment unit and discarded or used asfeedwater in a steam system. The scrubbed gas 311 is compressed in acompressor 312 to a pressure of about 23 bara. The compressed gas 313 isthen cooled 314, treated in a scrubber 316 and dehydrated 319 before itis further cooled 321 to a temperature where a portion of the CO₂ is inliquid form. This cooling is achieved by use of conventional, closed,industrial refrigeration systems (not shown in detail). The liquid CO₂in stream 322 is separated from the gases in a low temperature (−40-−55°C.) gravity based separator 323. In the specific example the temperatureis −50° C. and the pressure is 22.5 bar. The gas leaving the separator327 is heated 328, and expanded through a valve (not shown) to obtainthe operating pressure before it is mixed with the purified feed gas103. A small portion, typically 5%, of the recycled gas is discarded inorder to avoid build-up of non-combustible and non-condensable gases,typically N₂. The recycled gas typically consists of 32% H₂, 15% CO, 34%CO₂ and 18% N₂. The liquefied CO₂ 324 from the separator 323 is sent tostorage 325 from which it can be transported by ship or truck, oroptionally sequestered by pipeline. The liquefied CO₂ stream typicallyconsists of more than 98% CO₂. This specific embodiment of the presentinvention typically has a calculated electrical efficiency of around 60%(ac/LHV).

FIG. 4 is a schematic flow diagram of a specific embodiment of thepresent invention using a separation process based on high temperaturehydrogen selective membranes in a power plant. The fuel pretreatment101, mixing with recycle gas 357 and conversion in main SOFC 1 issimilar to the example described in FIG. 2. The gas turbine unit 201-209is also described above. In the present example the anode exhaust stream301 enters a hydrogen selective membrane unit 350 on the feed side at6.7 bara. The temperature is dependent on the membrane type selected andconventional cooling may be used to achieve it. Hydrogen is transferredthrough the membrane with a selectivity dependent on the membrane type.In the specific example the membrane is operating at a temperature of600° C. The hydrogen rich permeate gas typically contains 50% H₂′.Typically, the pressure on the permeate side is close to ambient and asweep gas 359 (preferably steam) is used to increase the driving force.The hydrogen rich permeate gas 351 is cooled in a heat exchanger 352 andwater is removed by a condenser or scrubber 354, before the scrubbed gas355 is compressed 360 to the operating pressure in a multistage, intercooled compressor and mixed with the clean fuel 103. The retentate gas358 consists of CO₂, H₂O, small amounts of H₂, CO and N₂ and is heatexchanged in 105 before water is removed by a condenser or scrubber 310.Additional coolers not shown are used to cool the gas. The scrubbed,CO₂-rich gas 361 is compressed 362, cooled 364, scrubbed 366 anddehydrated 368 before it is further compressed 370 to the desiredpressure for sequestration. The CO₂-rich gas produced in this systemtypically has a composition of 96% CO₂, 2% H₂, 1% CO and 1% N₂. Thespecific embodiment of the present invention typically has a calculatedelectrical efficiency of around 60% (ac/LHV).

FIG. 5 is a schematic flow diagram of a specific embodiment of thepresent invention using a separation process based on high temperatureselective membranes in a power plant and with a specific use of therecovered hydrogen. The process is as described for FIG. 4, but with thefollowing exception. The recovered and compressed hydrogen 357 is mixedwith the oxygen depleted air 20 and combusted in combustor 401, therebyincreasing the temperature of the resulting mixture of oxygen depletedair and steam 402 before entering the expander 207.

REFERENCES

-   [1] “A high-efficiency SOFC hybrid power system using the Mercury 50    ATS gas turbine” Wayne L. Lundberg and Stephen E. Veyo, Siemens    Westinghouse Power Generation, USA [2]    http://www.fuelcelltoday.com/FuelCellToday/Industrylnformation/Industrylnformation    External/IndustryInformationDisplayArticle/0,1168,318,00.html-   [3] http://www.ztekcorp.com/projects.htm-   [4] http://www.netl.doe.gov/scng/projects/hybrid/pubs/hyb40355.pdf-   [5] http://www.netl.doe.gov/scng/projects/hybrid/pubs/hyb40455.pdf

1. A method for treatment of gas exiting the anode side (301) of a solidoxide fuel cell stack (1) fuelled with a carbon containing fuel (100) ina power producing process, characterized in that the anode gas andcathode gas are kept separated by a seal system in the SOFC stack (4)and that the main part of the H₂ and CO in the anode exhaust (351) isseparated from the CO₂ in said exhaust (301) by a separation processbased on H₂ selective membranes (350).
 2. A method according to claim 1,characterized in that the anode exhaust (359) is treated such that mostof the CO₂ is not emitted to the atmosphere.
 3. A method according toclaim 1, characterized in that steam (361) is injected on the permeateside of the hydrogen selective membranes (350).
 4. A method according toclaim 1, characterized in that the recovered H₂ (355) is fed back to themain SOFC stack (1) and used as fuel.
 5. A method according to claim 1,characterized in the recovered H₂ (355) is used to heat the oxygendepleted air (206) entering the expander (207).
 6. A method according toclaim 1, characterized in that the recovered H₂ (355) is used to heatthe air entering the SOFC stack (205).
 7. A method according to claim 1,characterized in that the recovered H₂ (355) is exported as a salesproduct.
 8. A method according to claim 1, characterised in thatrecovered H₂ (355) is fed to the desulphurisation unit (101) to providenecessary hydrogen for hydrodesulphurisation.
 9. A method for treatmentof gas exiting the anode side (301) of a solid oxide fuel cell stack (1)fuelled with a carbon containing fuel (100) in a power producingprocess, characterised in that the anode gas and cathode gas are keptseparated by a seal system in the SOFC stack (4), that the main part ofthe H₂ and CO in the anode exhaust (301) is separated from the CO₂ insaid exhaust by a separation process based on compressing (312), drying(319) and cooling (321) to a pressure and temperature where most of theCO₂ is in liquid form (322) and subsequently is separated from the H₂and CO in a conventional gravity based separation process (323).
 10. Amethod according to claim 9, characterised in that the anode exhaust(301) is treated such that most of the CO₂ is not emitted to theatmosphere.
 11. A method according to claim 9, characterised in that therecovered H₂ an CO (329) is fed back to the main SOFC stack (1) and usedas fuel
 12. A method according to claim 9, characterised in that therecovered H₂ an CO (329) is removed in order to avoid build-up of gaseswhich are non-condensable and non-combustible.
 13. A method according toclaim 9, characterised in that the recovered H₂ an CO (329) is fed tothe desulphurisation unit (101) to provide the necessary hydrogen forhydrodesulphurisation.